UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ý☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20192021

or

o☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File No. 000-53177

Ridgewood Energy W Fund, LLC

(Exact name of registrant as specified in its charter)

14 Philips Parkway, Montvale, NJ 07645

(Address of principal executive offices) (Zip code)

(800) 942-5550

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Shares of LLC Membership Interest

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o☐ No x☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o☐ No x☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x☒ No o☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x☒ No o

☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.o ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso ☐ Nox

☒

There is no0 market for the shares of LLC Membership Interest in the Fund. As of March 3, 2020,February 28, 2022, there were 332.2918 shares of LLC Membership Interest outstanding.

RIDGEWOOD ENERGY W FUND, LLC
2019
2021 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy W Fund, LLC (the “Fund”) has incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections and statements relating to the Fund’s business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 that1995. Such forward-looking statements are based on current expectations and assumptions and are subject to risks and uncertainties that may cause actual results to differ materially from the forward-looking statements. You are therefore cautioned against relying on any such forward-looking statements. Forward-looking statements can generally be identified by words such as “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “will likely result,” and similar expressions and references to future periods. Examples of events that could cause actual results to differ materially from historical results or those anticipated include the impact on the Fund’s business and operations of the ongoing novel coronavirus (“COVID-19”) pandemic and any other future widespread health emergencies or public health crises such as pandemics and epidemics, weather conditions, such as hurricanes, changes in market and other conditions affecting the pricing, production and demand of oil and natural gas, the cost and availability of equipment, and changes in domestic and foreign governmental regulations, as well as other risks and uncertainties discussed in this Annual Report in Item 1. “Business” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.Operations.” Examples of forward-looking statements made herein include statements regarding projects, investments, insurance, capital expenditures and liquidity. Forward-looking statements made in this document speak only as of the date on which they are made. The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

PART I

Overview

The Fund is a Delaware limited liability company (“LLC”) formed on May 17, 2007 to primarily acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.

The Fund initiated its private placement offering on June 15, 2007, selling whole and fractional shares of membership interests (“Shares”), consisting of Limited Liability Shares of Membership Interests (“Limited Liability Shares”) and Investor GP Shares of Membership Interests (“Investor GP Shares”), primarily at $200 thousand per whole Share. The Limited Liability Shares and the Investor GP Shares constitute a single class of securities as defined in Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). In 2011, pursuant to the Fund’s limited liability company agreement (the “LLC Agreement”), Ridgewood Energy Corporation, as manager of the Fund, converted all then outstanding Investor GP Shares to Limited Liability Shares.  There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund’s LLC Agreement and applicable federal and state securities laws. The private placement offering was terminated on December 17, 2007. The Fund raised $66.0 million and, after payment of $10.8 million in offering fees, commissions and investment fees, the Fund had $55.2 million for investments and operating expenses.

Manager

Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) was founded in 1982. The Manager has direct and exclusive control over the management of the Fund’s operations. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for the Fund’s operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations, the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for the Fund’s operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. Historically, when the Fund sought project investments, the Manager located potential projects, conducted due diligence, and negotiated the investment transactions with respect to those projects. Additional information regarding the Manager is available through its website at www.ridgewoodenergy.com. No information on such website shall be deemed to be included or incorporated by reference into this Annual Report.

As compensation for its services, the Manager is entitled to receive an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. The Manager is entitled to receive the management fee from the Fund regardless of the Fund’s profitability in that year. Management fees during each of the years ended December 31, 20192021 and 20182020 were $0.9 million.$0.5 million and $0.7 million, respectively. Additionally, the Manager is entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during each of the years ended December 31, 20192021 and 20182020 were $0.8 million and $0.2 million, respectively.million.

In addition to the management fee, the Fund is required to pay all other expenses it may incur, including insurance premiums, expenses of preparing periodic reports for shareholders and the Securities and Exchange Commission (“SEC”), taxes, third-party legal, accounting and consulting fees, litigation expenses and other expenses.

Business Strategy

The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of oil and natural gas projects. The frequency and amount of such distributions are within the Manager’s discretion, subject to available cash flow from operations. The Fund, along with other exploration and production companies, has invested in the drilling and development of both shallow and deepwater oil and natural gas projects in the U.S. offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund’s ownership in its projects is recorded with the Bureau of Ocean Energy Management (“BOEM”), an agency of the United States Department of Interior (“Interior”), as a working interest, which is an undivided fractional interest in a lease block that provides the owner with the right to drill, produce and conduct operating activities and share in any resulting oil and natural gas production.

The Fund’s capital has been fully invested in projects. As a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which it currently has a working interest, as discussed below under the heading “Properties” in this Item 1. “Business” of this Annual Report.

Investment Committee

Ridgewood Energy maintains an investment committee consisting of sixfive employees of the Manager (the “Investment Committee”). The members of the Investment Committee provide operational, financial, scientific and technical oil and gas expertise to the Fund. One member of the Investment Committee is based out of the Manager’s Palm Beach, Florida office, one member is based out of the Manager’s Montvale, New Jersey office and fourthree members are based out of the Manager’s Houston, Texas office. The Investment Committee’s current activities with respect to the Fund are principally related to the development and operation of properties in which it already has a working interest.

Participation and Joint Operating Agreements

On behalf of the Fund, and with respect to the Fund’s projects, the Manager negotiated participation and joint operating agreements with the operators of each project. Under each joint operating agreement, proposals and decisions with respect to a project and related activities are generally made based on percentage ownership approvals and, although an operator’s percentage ownership may constitute a majority ownership, operators generally seek consensus relating to project decisions.

Project Information

The Fund’s existing projects are located in the waters of the Gulf of Mexico on the Outer Continental Shelf (“OCS”). The Outer Continental Shelf Lands Act (“OCSLA”), which was enacted in 1953, governs certain activities with respect to working interests and the exploration of oil and natural gas in the OCS. See further discussion under the heading “Regulation” in this Item 1. “Business” of this Annual Report.

Leases in the OCS are generally issued for a primary lease term of 5, 7 or 10 years, depending on the water depth of the lease block. Once a lessee drills a well and begins production, the lease term is extended for the duration of commercial production.

The lessee of a particular block, for the term of the lease, has the right to drill and develop exploratory wells and conduct other activities throughout the block. If the initial well on the block is successful, a lessee, or third-party operator for a project, may conduct additional geological studies and may determine to drill additional exploratory or development wells. If a development well is to be drilled in the block, each lessee owning working interests in the block must be offered the opportunity to participate in, and cover the costs of, the development well up to that particular lessee’s working interest ownership percentage.

Royalty Payments

Generally, and depending on the lease, working interest owners of an offshore oil and natural gas lease under the OCSLA pay a royalty of 12.5%, 16.67% or 18.75% to the U.S. Government through the Office of Natural Resources Revenue (“ONRR”). Other than the ONRR royalties, the Fund does not have material royalty burdens with the exception of the overriding royalty interests (“ORRI”) payable to the lender under and as required by the Fund’s credit agreement applicable to the Beta Project. See Note 43 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the credit agreement.

Deepwater Royalty Relief

In addition to the Royalty Relief Rule, the Deep WaterDeepwater Royalty Relief Act of 1995 (the “Deepwater Royalty Relief Act”) was enacted to promote exploration and production of oil and natural gas in the deepwater of the Gulf of Mexico and relieves eligible leases from paying royalties to the U.S. Government on certain defined amounts of deepwater production. The Deepwater Royalty Relief Act expired in the year 2000 but was extended for qualified leases by the BOEM to promote continued interest in deepwater. The Fund currently has two projects,one project, the Beta and Liberty projects,Project, which areis eligible for royalty relief under the Deepwater Royalty Relief Act. The Deepwater Royalty Relief Act does not apply to oil if the prices of oil exceed certain thresholds (currently estimated to be between $39.52$41.60 per barrel and $51.32$54.01 per barrel) adjusted annually for inflation. The Deepwater Royalty Relief Act does not apply to natural gas if the prices of natural gas exceed certain thresholds (currently estimated to be between $4.94$5.20 per mmbtu and $8.55$9.00 per mmbtu) adjusted annually for inflation.

Properties

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which the Fund owned a working interest as of December 31, 2019.2021. Productive wells are producing wells and wells mechanically capable of production. Gross wells are the total number of wells in which the Fund owns a working interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells, each of which produces both oil and natural gas, are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.

Acreage Data

The following table sets forth the Fund’s working interests in developed and undeveloped oil and natural gas acreage as of December 31, 2019.2021. Gross acres are the total number of acres in which the Fund owns a working interest. Net acres are the sum of the fractional working interests owned in gross acres. Ownership interests generally take the form of working interests in oil and natural gas leases that have varying terms. All of the Fund’s oil and natural gas acreage is located in the offshore waters of the Gulf of Mexico.

Information regarding the Fund’s current projects, all of which are located in the offshore waters of the Gulf of Mexico, is provided in the following table. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Liquidity Needs” for information regarding the funding of the Fund’s capital commitments.

Beta Project – Partial Sale of Working Interest

On August 10, 2018, the Fund entered into a purchase and sale agreement (“PSA”) to sell a portion of the Fund’s working interest in the Beta Project to Walter Oil & Gas Corporation and Gordy Oil Company (collectively the “Buyers”) with an effective date of January 1, 2018. Certain other funds managed by the Manager were also parties to the PSA. The Fund had a 3.0% working interest in the Beta Project and sold a 0.11% working interest to the Buyers for a total purchase price of $1.0 million, subject to purchase price and customary post-closing adjustments. The transaction closed on August 10, 2018 and the Fund received $0.9 million in cash, which included preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. During fourth quarter 2018, the Fund recognized a post-closing adjustment in the amount of $10 thousand, which was recorded as an adjustment to the purchase price.

The net carrying value of the working interest sold as of the closing date was approximately $0.7 million and the related asset retirement obligation was approximately $12 thousand. A gain to the Fund of $0.3 million was recognized during the year ended December 31, 2018, including post-closing adjustments. The proceeds from the sale were utilized by the Fund to repay a portion of the long-term debt outstanding under its credit agreement. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Liquidity Needs –Credit Agreement” for information regarding the Fund’s credit agreement.

Marketing/Customers

The Manager, on behalf of the Fund, markets the Fund’s oil and natural gas to third parties consistent with industry practice. The Fund utilizes Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. In 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third-party purchasers. The number of customers purchasing the Fund’s oil and natural gas may vary from time to time. Currently, the Fund has two major customers in the public market. Because a ready market exists for oil and natural gas, the Fund does not believe that the loss of any individual customer would have a material adverse effect on its financial position or results of operations. The Fund’s current producing projects areBeta Project is near existing transportation infrastructure and pipelines.

The Fund’s oil and natural gas generally is sold to its customers at prevailing market prices, which fluctuate with demand as a result of related industry variables.   The markets for, and prices of, oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence; therefore, it is impossible to predict the future price of oil and natural gas with any certainty.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Commodity Price Changes”,Changes,” “Results of Operations –Overview” and “Results of Operations –Oil and Gas Revenue” for information regarding the impact of prices on the Fund’s oil and gas revenue. In the past, the Fund has entered, and in the future, may enter into transactions or derivative contracts that establish a price floor for portions of its oil or natural gas production. 

Seasonality

Generally, the Fund’s business operations are not subject to seasonal fluctuations in the demand for oil and natural gas that would result in more of the Fund’s oil and natural gas being sold, or likely to be sold, during one or more particular months or seasons. Once a project is producing, the operator of the project extracts oil and natural gas reserves throughout the year. Once extracted, oil and natural gas can be sold at any time during the year.

However, notwithstanding the ability of the Fund’s projectsBeta Project to produce year-round, the Fund’s properties areproject is located in the Gulf of Mexico; therefore, its operations and cash flows may be significantly impacted by hurricanes and other inclement weather. Such events may also have a detrimental impact on third-party pipelines and processing facilities, upon which the Fund relies to transport and process the oil and natural gas it produces. The National Hurricane Center defines hurricane season in the Gulf of Mexico as June through November. TheIn the third quarter of 2021, Hurricane Ida passed directly through the corridor where the Fund’s Beta Project is located. Although the Fund did not experience any significant damage shut-ins, or production stoppagesfrom Hurricane Ida, the Beta Project needed to be shut-in in accordance with safety protocols as well as due to hurricane activity in 2019.the impact of the storm on third-party midstream and downstream infrastructure to which the Beta Project’s production flows.

Operators

The projects in which the Fund has invested are operated and controlled by unaffiliated third-party entities acting as operators. The operators are responsible for drilling, administration and production activities for leases jointly owned by working interest owners and act on behalf of all working interest owners under the terms of the applicable joint operating agreement. In certain circumstances, operators will enter into agreements with independent third-party subcontractors and suppliers to provide the various services required for operating leases. Currently, the Fund's properties areproperty is operated by LLOG Exploration Offshore, L.L.C. and Walter Oil & Gas Corporation.

Because the Fund does not operate any of the projects in which it has acquired a working interest, shareholders have to rely on the Manager to continue to manage the projects prudently, efficiently and fairly.

Insurance

The Manager has obtained what it believes to be adequate insurance for the funds that it manages to cover the risks associated with the funds’ passive investments, including those of the Fund. Although the Fund is not an operator, the Manager has, nonetheless, obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover its projects, as well as general liability, directors’ and officers’ liability and similar coverage for its business operations. However, there is no assurance that such insurance will be adequate to protect the Fund from material losses related to its projects. In addition, the Manager’s practice is to obtain insurance as a package that is intended to cover most, if not all, of the entities under its management. The Manager re-evaluates its insurance coverage on an annual basis. While the Manager believes it has obtained adequate insurance in accordance with customary industry practices, the possibility exists, depending on the extent of the insurable incident, that insurance coverage may not be sufficient to cover all losses. In addition, depending on the extent, nature and payment of any claims during a particular policy period to the Fund or its affiliates, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Fund in a given year.

Salvage Fund

The Fund deposits cash in a separate interest-bearing account, or salvage fund, to provide for its proportionate share of the cost of dismantling and removal of production platforms and facilities and plugging and abandoning the wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. As of December 31, 2019,2021, the Fund had $3.0$1.9 million invested in a salvage fund. On a monthly basis, the Fund contributes to the salvage fund a portion of the operating income from the Beta Project to fund its asset retirement obligations. Such contributions to the salvage fund will reduce the amount of cash distributions that could otherwise be made to investors by the Fund. Any portion of the salvage fund that remains after the Fund has paid for all of its asset retirement obligations will be distributed to the shareholders and the Manager. There are no restrictions on withdrawals from the salvage fund.

Competition

Competition exists in the acquisition of oil and natural gas leases and in all sectors of the oil and natural gas exploration and production industry. The Fund, through the Manager, has competed with other companies for the acquisition of leases, as well as percentage ownership interests in oil and natural gas working interests in the secondary market. The Fund does not anticipate the acquisition of any additional ownership interests in oil and natural gas working interests as its capital has been fully allocated to current and past projects.

Employees

The Fund has no employees. The Manager operates and manages the Fund.

Offices

The administrative office of both the Fund and the Manager is located at 14 Philips Parkway, Montvale, NJ 07645, and their phone number is 800-942-5550. The Manager leases additional office space at 230 Royal Palm Way, Suite 102, Palm Beach, FL, 33480 and 1254 Enclave Parkway, Houston, TX 77077. In addition, the Manager maintains an additional office lease that is used for administrative purposes for the Fund and other funds managed by the Manager.

Regulation

Oil and natural gas exploration, development, production and transportation activities are subject to extensive federal and state laws and regulations. Regulations governing exploration and development activities require, among other things, the Fund’s operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects, the restoration of properties upon which projects are drilled, and the plugging and abandoning of projects are also subject to regulations.regulation. The Fund owns projects that are located in the offshore waters of the Gulf of Mexico on the OCS. The Fund’s operations and activities are therefore governed by the OCSLA and certain other laws and regulations.

Outer Continental Shelf Lands Act

Under the OCSLA, the United States federal government has jurisdiction over oil and natural gas development on the OCS. As a result, the United States Secretary of the Interior is empowered to sell exploration, development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding process. Such activity is conducted by the BOEM. Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”) pursuant to regulations promulgated under the OCSLA. The OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. BSEE regulates the design and operation of well control and other equipment at offshore production sites, implementation of safety and environmental management systems, and mandatory third-party compliance audits, among other requirements. BSEE adopted strict requirements for subsea drilling production equipment and had proposed new requirements to implement equipment reliability improvements, building upon enhanced industry standards for blowout preventers and blowout prevention technologies, and reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment. BSEE has also published a policy statement on safety culture with nine characteristics of a robust safety culture. In May 2019, BSEE adopted a final rule revising standards for blowout prevention systems and other well controls pertaining to offshore activities (the “2019 Well Control Rule”). The 2019 Well Control Rule became effective July 15, 2019, however compliance with certain provisions was deferred until 2021 or thereafter as specified in those provisions. The 2019 Well Control Rule imposes new requirements relating to, among other things, well design, well control, casing, cementing, real-time well monitoring and subsea containment. The 2019 Well Control Rule applies directly to operators as opposed to non-operators. On September 28, 2018, the BSEE published a final rule revising regulations relating to oil and natural gas production safety systems, subsurface safety devices and safety device testing (referred to as “Subpart H”); the rule was effective December 27, 2018. Given the fact that compliance with the 2019 Well Control Rule and Subpart H is the responsibility of the operators and the exploration and development of each well is different, the future costs associated with compliance that will be incurred by non-operators, such as the Fund, cannot be determined or estimated. On December 4, 2020, BOEM published a Record of Decision (“ROD”) for the final programmatic environmental impact statement for geological and geophysical survey activities in the Gulf of Mexico and adjacent state waters. The ROD provides for additional mitigation measures for application for future BOEM issued permits or authorizations toward further minimizing impacts of such geological and geophysical survey activities on marine resources. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties, which civil penalties were increased and adjusted for inflation on March 2, 2018,April 15, 2021, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities, delay or restriction of activities can result from either governmental or citizen prosecution. 

Effective January 20, 2021, the Secretary of the Interior issued Order No. 3395 under the authority of Section 2 of Reorganization Plan No. 3 of 1950 (64 Stat. 1262) consistent with 200 DM 1 for the purpose of implementing a targeted and time-limited elevation of relevant decisions at the Interior for review.  One item under review is temporarily suspending the issuance of any onshore or offshore fossil fuel authorization, including but not limited to a lease, amendment to a lease, affirmative extension of a lease, contract, or other agreement, or permit to drill.  This does not limit existing operations under valid leases.  Prior to Order No. 3395 expiring on March 21, 2021, the Secretary of the Interior issued a letter to Bureau Directors dated March 19, 2021 confirming the matters that still need review and approval of the Office of the Assistant Secretary for Land and Minerals Management. Such matters include extension of applications for permit to drill, Records of Decision, lease sale notices and lease suspensions. As the Fund’s capital has been fully invested and it does not expect to invest in any new projects, the Fund believes the secretarial order will not have an impact on the Fund’s operations or financial condition.

BOEM Notice to Lessees on Supplemental BondingFinancial Assurance Requirements

On July 14, 2016, the BOEM issued a Notice to Lessees (“NTL 2016-N01”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of userights-of-use and easements on the OCS (“Lessees”).  Generally, NTL 2016-N01 (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security, and (iv) replaced the waiver system with one of self-insurance.  The rule became effective as of September 12, 2016; however, on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances.  On May 1, 2017, the Secretary of the U.S. Department of the Interior (“Interior”) directed the BOEM to complete a review of NTL 2016-N01, to provide a report to certain Interior personnel describing the results of the review and options for revising or rescinding NTL 2016-N01, and to keep the implementation timeline extension in effect pending the completion of the review of NTL 2016-N01 by the identified Interior personnel. 

On June 22, 2017,October 16, 2020, BOEM and BSEE published a proposed new rule at 85 FR 65904 on Risk, Management, Financial Assurance and Loss Prevention, addressing the streamlining of evaluation criteria when determining whether oil, gas and sulfur leases, right-of-use and easement grant holders, and pipeline right-of-way grant holders may be required to provide bonds or other security above the prescribed amounts for base bonds to ensure compliance with the Lessees’ obligations, primarily decommissioning obligations. The proposed rule was significantly less stringent with respect to financial assurance than NTL 2016-N01. To date, the BOEM announcedis not currently implementing NTL 2016-N01 and its status is uncertain, but has indicated that it is reviewing the implementation timeline extension will remain in effect pendingproposed rule.

Notwithstanding the completion of the review of NTL 2016-N01. As of December 31, 2019, the BOEM has not lifted its suspension of the implementation of NTL 2016-N01.  The impactuncertain status of NTL 2016-N01, if enforced without change or amendment,BOEM had continued under existing law to review supplemental financial assurance requirements relative to sole liability properties (i.e., properties in which only one company is liable for decommissioning).  However, on August 18, 2021, the BOEM issued a Note to Stakeholders in which the BOEM stated that it was expanding its financial assurance efforts beyond sole liability projects to include “supplemental financial assurance of certain high-risk, non-sole liability properties” (those properties with more than one company potentially liable for decommissioning costs). The BOEM identified (i) inactive properties, (ii) those with less than five years of production left, and (iii) those with damaged infrastructure, as being high-risk, non-sole liability properties and for which supplemental financial assurance may be required.  The BOEM may require the Fund to fully secure all of its potential abandonment liabilities, to the BOEM’s satisfaction using one or more of the enumerated methods for doing so.  Potentially thiswhich potentially could increase costs to the Fund if theFund. The Fund is requirednot able to obtain additional supplemental bonding, fund escrow accountsevaluate the impact of the proposed new rule on its operations or obtain letters of credit.financial condition until a final rule is issued or some other definitive action is taken by the Interior or BOEM.

Sales and Transportation of Oil and Natural Gas

The Fund, directly or indirectly through affiliated entities, sells its proportionate share of oil and natural gas to the market and receives market prices from such sales. These sales are not currently subject to regulation by any federal or state agency. However, in order for the Fund to make such sales, it is dependent upon unaffiliated pipeline companies whose rates, terms and conditions of transport are subject to regulation by the Federal Energy Regulatory Commission. Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service-based. In some circumstances, rates can be agreed upon pursuant to settlement. Thus, the rates that pipelines charge the Fund, although regulated, are beyond the Fund’s control. Nevertheless, such rates would apply uniformly to all transporters on that pipeline and, as a result, management does not anticipate that the impact to the Fund of any changes in such rates, terms or conditions would be materially different than the impact to other oil or natural gas producers and marketers.

Environmental Matters and Regulation

The Fund’s operations are subject to pervasive environmental laws and regulations governing, among other things, the discharge of materials into the air and water, the handling and managing of waste materials, and the protection of aquatic species and habitats. While most of the activities to which these federal, state and local environmental laws and regulations apply are conducted by the operators on the Fund’s behalf, the Fund shares the liability along with its other working interest owners for environmental damageimpacts attributable to the Fund’s operations. The environmental laws and regulations to which its operations are subject may require the Fund, or the operator, to acquire permits to commence drilling operations, restrict or prohibit the release of certain materials or substances into the environment, impose the installation of certain environmental control devices, require certain remedial measures to prevent pollution and other discharges such as the plugging of abandoned projects and, finally, impose in some instances severe penalties, fines and liabilities for the environmental damage that may be caused by, or impacts that may be attributable to, the Fund’s projects.Beta Project.

Some of the environmental laws that apply to oil and natural gas exploration and production are described below:

Oil Pollution Act. The Oil Pollution Act of 1990, as amended (the “OPA”), amends Section 311 of the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and was enacted in response to the numerous tanker spills that occurred in the 1980s, including the Exxon Valdez spill, that occurred in the 1980s.spill. Among other things, the OPA clarifies the federal response authority to, and defines penalties for, such spills. OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permit holder of the area in which an offshore facility is located. The OPA, andwith regulations promulgated thereunder, establishes a liability limit for onshore facilities and deepwater ports of $672.51 million (effective as of November 12, 2019), while the liability limit for a responsible party for offshore facilities, including any offshore pipeline, is equal to all removal costs plus up to $137.66 million in other damages for each incident. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up. Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. A failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. The Fund is not aware of any action or event that would subject us to liability under the OPA. Compliance with the OPA’s financial assurance and other operating requirements has not had, and the Fund believes will not in the future have, a material impact on the Fund’s operations or financial condition.

Clean Water Act. Generally, the Clean Water Act, as well as analogous state requirements, imposes liability for the unauthorized discharge of pollutants, including petroleum products, into the surface and coastal U.S. waters, except in strict conformance with discharge permits issued by the federal or delegated state agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. On December 11, 2018, the Environmental Protection Agency (“EPA”) and Department of the Army (“Army”) proposed a revised definition of “waters of the United States” (“WOTUS”), clarifying the limits of federal authority under the Clean Water Act. The scope of this authority, as defined under a 2015 rule, was challenged in several federal district court actions and therefore was repealed by the EPA and Department of the Army on September 12, 2019. The repeal, which became effective on December 23, 2019, restored the previous regulation to how it existed prior to finalization of the 2015 Rule. The current2020 Navigable Waters Protection Rule (“NWPR”) was then promulgated, with a replacement definition of WOTUS, and went into effect on June 22, 2020. A recent executive order revoked a prior executive order related to WOTUS and directed agencies to review certain actions, including the NWPR. On June 9, 2021, the Department of the Army and EPA announced their intent to initiate a new rulemaking process that would both restore a pre-2015 Clean Water Rule and develop a new rule to establish a new WOTUS definition, and then sought feedback from stakeholders. On September 3, 2021, following a court order vacating the NWPR, the Department of the Army and EPA announced that they had halted implementation of the NWPR and would interpret WOTUS consistent with the pre-2015 regulatory regime. On November 18, 2021, the EPA and the Department of the Army announced the signing of a proposed revision will berule to revise the subjectdefinition of WOTUS. On December 7, 2021, the proposed rule was published in the Federal Register with a 60-day public comment period once publishedthat closed on February 7, 2022. A final rule is expected to be issued by the EPA later in the Federal Register.2022. The Fund’s operators are responsible for compliance with the Clean Water Act, although the Fund may be liable for any failure of the operator to do so.

Clean Air Act. The Federal Clean Air Act of 1970, as amended (the “Clean Air Act”), as well as analogous state requirements, restricts the emission of certain air pollutants. Prior to constructing new facilities, permits may be required before work can commence and existing facilities may be required to incur additional capital costs to add equipment to ensure and maintain compliance. OCSLA provides the Secretary of the Interior, through BOEM, with the statutory authority to regulate air quality over the Central and Western Gulf of Mexico. On June 5, 2020, BOEM published the Offshore Air Quality Rule, which revised the air quality regulations applicable to activities that BOEM authorizes on the OCS in the Western Gulf of Mexico. The Offshore Air Quality Rule, effective on July 6, 2020, brings the air quality standards that lessees and operators must meet in order to operate in the Western Gulf of Mexico into compliance with the current National Ambient Air Quality Standards and benchmarks set forth by the EPA under the Clean Air Act. As a result, the Fund’s operations may be required to incur additional costs to comply with the Clean Air Act and comparable state requirements.

International Marine Organization 2020. In 2016, the International Marine Organization (“IMO”), a United Nations (“UN”) Agency, instituted a reduction in the sulfur specifications for global marine fuels from 3.5% to 0.5% effective January 1, 2020 in order to reduce the emissions of sulfur to the atmosphere. Shipping companies have the option to buy low sulfur fuel or install scrubbers to lower sulfur emissions to comply with the new regulation. UN member states (174 countries) are responsible for monitoring the compliance of the shipping community with this new regulation. The impact to the Fund from this new regulation could be that heavier sour crudes, such as from the Beta Project, could fall in value relative to lighter sweet crudes as a result of excess high sulfur fuel on the market and subsequent refinery crude slate changes. However, the price of heavier sour crudes in the market continues to be supported by tightness in supply for such crude, new refinery capacity consuming medium/high sulfur crudes and refinery optimization around high sulfur products. As such, the Fund believes IMO 2020 will not in the future have a material impact on the Fund’s operations or financial condition.

Climate Change. The oil and gas industry is subject to federal and state greenhouse gas monitoring, reporting and emissions control requirements. The current state of international climate initiatives and federal and state actions, as well as litigation developments including matters before the U.S. Supreme Court in the 2021-2022 term, presents challenges to assessing the impact to the Fund’s operations in relation to future international agreements, federal and state legislation, and other new requirements. Future restrictions on emissions of greenhouse gases could have an impact on future operations.

Other Environmental Laws. In addition to the above, the Fund’s operations may be subject to theResource Conservation and Recovery Act of 1976, as amended, which regulates the generation, transportation, treatment, storage, disposal and cleanup of certain hazardous wastes, as well as theComprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, which imposes joint and several liability without regard to fault or legality of conduct on classes of persons who are considered responsible for the release of a hazardous substance into the environment. Additionally, certain of the Fund’s operations (or actions relating to same) may be subject to the National Environmental Policy Act (“NEPA”), which requires in general that federal agencies assess the environmental effects of proposed federal actions, typically in the context of projects requiring a federal permit or authorization. Development of oil and gas pipelines are among the types of activities that could trigger NEPA and require such review. On July 16, 2020, the Council on Environmental Quality (“CEQ”) published a final rule to amend NEPA regulations to, among other things, clarify when NEPA applies, amend the definition of “effect” in the agency review, streamline the NEPA review, and provide additional flexibility for public involvement. Subsequently, in 2021, the CEQ withdrew the 2020 rule and is now engaged in a comprehensive review of the 2020 rule. The CEQ issued an Interim Final Rule on June 29, 2021, which extended the deadline by two years (to September 14, 2023) for federal agencies to develop or update their NEPA implementing procedures to conform to the CEQ regulations. The Fund’s operations may be subject to analogous and comparable state laws and regulations, in addition to these federal statutes and regulations.

The above represents a brief outline of significant environmental laws that may apply to the Fund’s operations. The Fund believes that its operators are in compliance with the relevant requirements of each of these environmental laws and the regulations promulgated thereunder. The Fund does not believe that its environmental, health and safety risks are materially different from those of comparable companies in the United States in the offshore oil and gas industry. However, there are no assurances that the environmental laws described above (including litigation developments relating to same) will not result in curtailment of production; material increases in the costs of production, development or exploration; enforcement actions or other penalties as a result of any non-compliance with any such regulations; or otherwise have a material adverse effect on the Fund’s operating results and cash flows.

Dodd-Frank Act.The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market and, in addition, requires certain additional Securities and Exchange Commission (“SEC”)SEC reporting requirements.

On February 3, 2017, the “Presidential Executive Order on Core Principles for Regulating the United States Financial System” (the “Order”) was issued to review the Dodd-Frank Act.  A series of reports were issued by the U.S. Department of the Treasury in 2017 pursuant to the Order generally recommending the harmonization, balancing and streamlining of rules and regulations relating to, among other things, the over-the-counter derivatives market. The Fund cannot predict at this time what regulations or portions of the law relating to the over-the-counter derivatives market, if any, will be changed as a result of the Order. Any changes in the law or regulation as a result of the Order could result in a repeal, amendment to or delayed implementation of the Dodd-Frank Act.

Currently, under the LLC Agreement, the Fund has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production. The Dodd-Frank Act mandates that many derivatives be executed in regulated markets and submitted for clearing to regulated clearinghouses. Derivatives will be subject to minimum daily margin requirements set by the relevant clearinghouse and, potentially, by the SEC or the U.S. Commodity Futures Trading Commission (“CFTC”), and derivatives dealers may demand the unilateral ability to increase margin requirements beyond any regulatory or clearinghouse minimums. In addition, as required by the Dodd-Frank Act, the CFTC has set “speculative position limits” (which are limits imposed on the maximum net long or net short speculative positions that a person may hold or control with respect to futures or options contracts traded on the U.S. commodities exchange) with respect to most energy contracts. These requirements under the Dodd-Frank Act could significantly increase the cost of any derivatives transactions of the Fund (including through requirements to post collateral, which could adversely affect the Fund’s liquidity), materially alter the terms of derivatives transactions and make it more difficult for the Fund to enter into customized transactions, cause the Fund to liquidate certain positions it may hold, reduce the ability of the Fund to protect against price volatility and other risks by making certain hedging strategies impossible or so costly that they are not economical to implement, and increase the Fund’s exposure to less creditworthy counterparties. If as a result of the legislation and regulations, the Fund alters any hedging program that may be in effect from time to time, the Fund’s operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Fund’s performance. The Fund is not currently, and has not been during 2019,2021, or at any time since 2012, a party to any derivative instruments or hedging programs.

The Dodd-Frank Act also requiredOn December 16, 2020, the SEC to issue rules requiringadopted the final resource extraction issuersdisclosure rules, which became effective on March 16, 2021. As adopted, the rule requires domestic or foreign reporting issuer to disclose annually information relating to certain payments made by the issuer of a subsidiary or entity controlled by the issuer to the U.S. federal government or a foreign government forif the purpose ofissuer engages in the commercial development of oil, natural gas, or minerals. Rules issued by the SEC in 2012 were subsequently vacated in federal court in 2013.  On June 27, 2016, the SEC adopted amended resource extraction disclosure rules pursuant to Section 1504 of the Dodd-Frank Act. However, on February 14, 2017,The Fund, as a bill was passed by the United States Congress eliminating the SEC resource extraction disclosure rules. The SEC had one year to issue replacement rules to implement Section 1504 of the Dodd-Frank Act. No replacement rules were proposed or issued by the SEC.smaller reporting company, is exempt from complying with this rule.

Not required.

None.

The information regarding the Fund’s properties that is contained in Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties,” is incorporated herein by reference.

Drilling Activity

The following table sets forth the Fund’s drilling activity during the years ended December 31, 2019 and 2018. Gross wells are the total number of wells in which the Fund has a working interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells, which produce both oil and natural gas, are located in the offshore waters of the Gulf of Mexico. During the years ended December 31, 20192021 and 2018,2020, the Fund had no drilling activity for exploratory and developmental wells.

Unaudited Oil and Gas Reserve Quantities

The preparation of the Fund’s oil and gas reserve estimates are completed in accordance with the Fund’s internal control procedures over reserve estimation.  Such control procedures include: 1) verification of input data that is provided to an independent petroleum engineering firm; 2) engagement of well-qualified and independent reservoir engineers for preparation of reserve reports annually in accordance with SEC reserve estimation guidelines; and 3) a review of the reserve estimates by a third-party independent petroleum engineering firm.

The Manager’s primary technical person in charge of overseeing the Fund’s reserve estimates has a B.S. degree in Petroleum Engineering, a Master of Business Administration, and is a member of the Society of Petroleum Engineers, the Association of American Drilling Engineers and the American Petroleum Institute. With over thirty years of industry experience, he is currently responsible for reserve reporting, engineering and economic evaluation of exploration and development opportunities, and the oversight of drilling and production operations.

The Fund’s reserve estimates as of December 31, 20192021 and 20182020 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from NSAI, which is filed as Exhibit 99.1 to this Annual Report, and is incorporated herein by reference.

Proved Reserves. Proved oil and gas reserves are estimated quantities of oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  Proved developed oil and gas reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are proved reserves expected to be recovered through new wells on undrilled acreage, or through existing wells where a relatively major expenditure is required for recompletion. The information regarding the Fund’s proved reserves, which is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Critical Accounting Estimates –Proved Reserves,”, is incorporated herein by reference.  The information regarding the Fund’s unaudited net quantities of proved developed and undeveloped reserves, which is contained in Table III in the “Supplementary Financial Information – Information about Oil and Gas Producing Activities – Unaudited” included in Item 8. “Financial Statements and Supplementary Data” of this Annual Report, is incorporated herein by reference. 

Proved Undeveloped Reserves. As of December 31, 20192021, the Fund had proved undeveloped reserves related to the Beta Project totaling 0.1 million barrels of oil, 7 thousand barrels of natural gas liquid (“NGL”) and 2018,34 thousand mcf of natural gas. As of December 31, 2020, the Fund did not have any proved undeveloped reserves. The Beta Project was determined to be a discovery in 2012 and commenced production in 2016.

The proved undeveloped reserves relating to the Beta Project, which were initially assigned at the end of the year 2021, are associated with planned well recompletions. The Fund expects the recompletion operations to be completed in 2022 and 2028.

Information regarding estimated future development costs relating to the Beta Project, which is contained in Item 1. “Business” of this Annual Report under the heading “Properties,” is incorporated herein by reference. Estimated future development costs include capital spending on planned well recompletions.

Production and Prices

The information regarding the Fund’s production of oil and natural gas, and certain price and cost information during the years ended December 31, 20192021 and 20182020 that is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Results of Operations –Overview” and “Results of Operations –Operating Expenses” is incorporated herein by reference. 

Delivery Commitments

As of December 31, 2019,2021, the Fund had no delivery obligations or delivery commitments under any existing contracts.

None.

None.

PART II

ITEM 5.       MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is currently no established public trading market for the Shares. As of January 31, 2020,2022, there were 859874 shareholders of record of the Fund.

Distributions are made in accordance with the provisions of the LLC Agreement. At various times throughout the year, the Manager determines whether there is sufficient available cash, as defined in the LLC Agreement, for distribution to shareholders. Distributions may be impacted by amounts of future capital required for the costs associated with the well recompletions for the Beta Project, as budgeted, as well as the funding of estimated asset retirement obligationsobligations. Distributions may also be impacted by fluctuations in oil and amounts reserved to provide for the borrowing repayments for the Fund’s credit agreement applicable to the Beta Project, as described in Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report.natural gas commodity prices. There is no requirement to distribute available cash and, as such, available cash is distributed to the extent and at such times as the Manager believes is advisable. During the years ended December 31, 20192021 and 2018,2020, the Fund paid distributions totaling $5.5$1.6 million and $1.3$1.1 million, respectively.

Not required.

ITEM 7.      MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview of the Fund’s Business

The Fund was organized primarily to acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of oil and natural gas projects. Distributions to shareholders, if any, are funded from available cash from operations, as defined in the Fund’s LLC Agreement, and the frequency and amount are within the Manager’s discretion. The Fund’s capital has been fully allocated to its projects. As a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which it currently has a working interest.

The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for the Fund’s operations. The Manager does not currently, nor is there any plan to, operate any project in which the Fund participates. The Manager enters into operating agreements with third-party operators for the management of all development and producing operations, as appropriate. The Manager also participates in distributions. See Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties” for more information regarding the projects of the Fund.

Market Conditions and COVID-19

The country is now two full years into the COVID-19 pandemic, and the outlook for the oil market, and the global economy in general, depends enormously on the country’s forward path out of it. During 2020, the outbreak of COVID-19 as a global pandemic and the lockdown measures and industrial slowdown around the world contributed to an economic downturn, significant drop in oil and natural gas demand and, together with the failure of an alliance between the Saudi Arabia-led Organization of Petroleum Exporting Countries (“OPEC”) and Russia to reach an agreement on oil production volumes resulted in an oil “price war,” caused oil prices to collapse to their lowest level in April 2020 as compared to the past several years. The period of low oil and natural gas commodity prices during 2020 negatively impacted cash flow generated by the Fund’s projects. On April 12, 2020, and throughout 2020, OPEC and Russia agreed and implemented oil production cuts to stabilize the oil market. Since then, the oil market has stabilized and strengthened with oil prices gradually rising throughout the rest of 2020.

During 2021, oil prices have continued to strengthen supported by a slow recovery in demand with the easing of lock-down measures and the rollout of COVID-19 vaccines, market-driven supply cutbacks in the upstream oil sector globally and the effective ongoing supply-side management by OPEC, which played an enormous role in stabilizing world oil markets over the past two years. OPEC and non-OPEC countries continue to signal effective cooperation at managing output to balance the market, even if demand growth stumbles going forward. Looking ahead, these factors indicate a more balanced market going into 2022. However, the COVID-19 pandemic and the new variants of the virus, specifically the Omicron variant, are still impacting countries, supply chains and commodities markets, in addition to the global financial markets. Different outcome of response to the new variants of the virus would have radically different impacts on global economic growth and the performance of financial markets as the market enters 2022. In addition, uncertainty still exists depending on actions taken by OPEC and non-OPEC countries in supporting a balanced global oil supply. However, because the Fund owns the Beta Project with no debt and the project is a long-lived asset that is expected to produce over many years with relatively low operating costs, the Fund believes that it is positioned to weather this period of uncertainty and volatility from the COVID-19 pandemic and global oil market.

The ultimate extent of the impact of the COVID-19 pandemic and resulting market disruption to the Fund’s operating results and cash flows continue to be unknown and unpredictable as it depends largely on future developments, including the duration and spread of COVID-19 and the related impact on the oil and gas industry, the impact of governmental actions designed to prevent the spread of COVID-19 and the development, availability, timely distribution and acceptance of effective treatments and vaccines worldwide. If oil and natural gas commodity prices and the overall global economy, including financial markets therein, are further adversely impacted by the COVID-19 pandemic for a prolonged period, the Fund, its operators and other working interest partners’ financial performance results may be materially adversely affected, which could affect the Fund’s liquidity and expected operating results.

Commodity Price Changes

Changes in oil and natural gas commodity prices may significantly affect liquidity and expected operating results. Declines in oil and natural gas commodity prices not only reduce revenues and profits but could also reduce the quantities of reserves that are commercially recoverable and result in non-cash charges to earnings due to impairment.impairment and higher depletion rates.

Oil and natural gas commodity prices have been subject to significant fluctuationsvolatility during the past several years.two years primarily attributable to the COVID-19 pandemic. Despite operating in a volatile commodity price environment, the Fund achieved the milestone of full repayment of its debt related to the Beta Project well ahead of the debt’s December 31, 2022 maturity date. Thus, having repaid the loan as of December 31, 2021, the Fund anticipates that more of the cash flow generated from the Beta Project will be available for distribution. The Fund also anticipates price cyclicality in its planning and believes it is well positioned to withstand price volatility. The Fund will continue to closely manage and coordinate its capital spending estimates within its expected cash flows to provide for future developmentthe costs ofassociated with the well recompletions for the Beta Project, as budgeted. See “Results of Operations” under this Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information on the average oil and natural gas prices received by the Fund during the years ended December 31, 20192021 and 20182020 and the effect of such average prices on the Fund’s results of operations. IfAlthough oil and natural gas commodity prices decline, even if only for a short period of time,have significantly improved from historic lows in 2020, the Fund’s results of operations and liquidity willmay be materially adversely impacted.impacted if there is a significant decrease in pricing due to the COVID-19 pandemic.

Market pricing for oil and natural gas is volatile and is likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence. Therefore, it is impossible to predict the future price of oil and natural gas with any certainty. Factors affecting market pricing for oil and natural gas include:

Critical Accounting Estimates

The discussion and analysis of the Fund’s financial condition and results of operations are based upon the Fund’s financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Fund’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of its revenues and expenses during the periods presented.  The Fund evaluates these estimates and assumptions on an ongoing basis. The Fund bases its estimates and assumptions on historical experience and on various other factors that the Fund believes to be reasonable at the time the estimates and assumptions are made. However, future events and actual results may differ from these estimates and assumptions and such differences may have a material impact on the results of operations, financial position or cash flows.  See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for a discussion of the Fund’s significant accounting policies. The following is a discussion of the accounting policies and estimates the Fund believes have had or are most significant.

Accounting for Acquisition, Exploration and Development Costs

Acquisition, exploration and development costs are accounted for usingreasonably likely to have a material impact on the successful efforts method. CostsFund’s financial position or results of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. Annual lease rentals and exploration expenses are expensed as incurred.operations.

Proved Reserves

Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depletion and amortization.amortization and estimated future cash flows of oil and gas properties used to test for impairment. Annually, the Fund engages an independent petroleum engineering firm to perform a comprehensive study of the Fund’s proved properties to determine the quantities of reserves and the period over which such reserves will be recoverable. The Fund’s estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues and net cash flows, rates of production and timing of development expenditures, including many factors beyond the Fund’s control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reservereserves estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, oil and natural gas commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenues and net cash flows to change.

Asset Retirement Obligations

Asset retirement obligations include costs to plug and abandon the Fund’s wells and to dismantle and relocate or dispose of the Fund’s production platforms and related structures and restoration costs of land and seabed. The Fund develops estimates of these costs based upon the type of production structure, water depth, reservoir depth and characteristics and ongoing discussions with the wells’ operators. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires significant judgment that is subject to future revisions based upon numerous factors such as the timing of settlements, the credit-adjusted risk-free rates used and inflation rates, including changing technology and the political and regulatory environment. Estimates are reviewed annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates.

Impairment of Long-Lived Assets

The Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of the assetsits oil and gas properties may not be recoverable.  Impairments are determinedRecoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the assetsoil and gas properties at the time of the review.  If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the assetoil and gas properties is impaired, and written down to fair value. Fair value which is determined using a valuation techniquetechniques that considersinclude both market and income approaches and usesuse Level 3 inputs.  The fair value determinations require considerable judgment and are sensitive to change.  Different pricing assumptions, reserve estimates of oil and natural gas reserves and future development costs or discount rates could result in a different calculatedsignificant impact on the amount of impairment.

Results of Operations

The following table summarizes the Fund’s results of operations during the years ended December 31, 20192021 and 2018,2020, and should be read in conjunction with the Fund’s financial statements and the notes thereto included within Item 8. “Financial Statements and Supplementary Data” in this Annual Report.

Overview. The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the years ended December 31, 20192021 and 2018. Natural gas liquid (“NGL”)2020. NGL sales are included within gas sales.

The increasedecreases in the number of wells producing, production days wasand oil and gas volumes noted in the table above were primarily related to the commencementLiberty Project, which reached the end of production of two wellsits productive life during first quarter 2020. In addition, the decrease in gas volumes was also attributable to the Beta Project, one well during third quarter 2018 and one well during first quarter 2019. The decreaseswhich is experiencing a natural decline in oil and gas sales volumes were related to the Beta and Liberty projects. The decrease in the Beta Project production was primarily related to the partial sale of working interest in the project during third quarter 2018 coupled with periodic shut-ins during first half 2019the shut-in of production from one of the project’s wells since May 2021 due to certain drilling and completion operations performed at the project’srecompletion work. The recompleted well returned to production facility. The Liberty Project experienced a decrease in production primarily as a result of shut-ins during 2019 due to mechanical work.late-September 2021. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.

Oil and Gas Revenue. Oil and gas revenue during the year ended December 31, 20192021 was $9.0$5.7 million, a decreasean increase of $3.0$2.1 million from the year ended December 31, 2018.2020. The decreaseincrease was attributable to decreased sales volume totaling $2.0 million coupled with decreasedincreased oil and gas prices totaling $1.0$2.5 million, partially offset by decreased sales volume totaling $0.4 million.

See“Overview” above for factors that impact the oil and gas revenue volume and rate variances.

Other Revenue. Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with an affiliated entityentities and other third parties. See Note 32 of “Notes to Financial Statements” – “Related Parties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information.

Depletion and Amortization. Depletion and amortization during the year ended December 31, 20192021 was $3.3$3.9 million, a decreasean increase of $1.8$0.4 million from the year ended December 31, 2018.2020. The decreaseincrease was primarily attributable to a decrease in production volumes totaling $0.9 million coupled with a decreasean increase in the average depletion rate totaling $0.9 million, partially offset by adjustments to the asset retirement obligation related to a fully depleted property totaling $0.5 million. The decreaseincrease in the average depletion rate was primarily attributable to the changes in reservereserves estimates provided annually by the Fund’s independent petroleum engineers. Depletion and amortization was also impacted byengineers coupled with the partial salehigher cost of working interest inreserves from the Beta Project primarily due to the recompletion costs incurred for one of the project’s wells during third quarter 2018.2021.

See“Overview” above for certain factors that impact the depletion and amortization volume and rate variances. Reserves estimates may also be impacted by significant declines in oil and natural gas commodity prices due to the COVID-19 pandemic, which could result in higher depletion rates.

Operating Expenses.Operating expenses represent costs specifically identifiable or allocable to the Fund’s wells, as detailed in the following table.

Lease operating expense and transportation and processing expense relate to the Fund’s producing projects. Insurance expense represents premiums related to the Fund’s projects, which vary depending upon the number of wells producing or drilling. Workover expense represents costs to restore or stimulate production of existing reserves. Accretion expense relates to the asset retirement obligations established for the Fund’s oil and gas properties. Workover expense represents costs to restore or stimulate production of existing reserves.

Production costs, which include lease operating expense, transportation and processing expense and insurance expense, were $1.3$0.7 million ($6.677.07 per barrel of oil equivalent or “BOE”) during the year ended December 31, 2019,2021, compared to $1.4$0.9 million ($6.148.58 per BOE) during the year ended December 31, 2018. Production2020.

The decreases in production costs and production costs per BOE were relatively consistent during the year ended December 31, 20192021 compared to the year ended December 31, 2018.2020 were primarily attributable to the Liberty Project, which reached the end of its productive life during first quarter 2020.

See“Overview” above for factors that impact oil and natural gas production.

Management Fees to Affiliate.An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments, is paid monthly to the Manager. All or a portion of such fee may be temporarily waived by the Manager to accommodate the Fund’s short-term commitments.

General and Administrative Expenses. General and administrative expenses represent costs specifically identifiable or allocable to the Fund, such as accounting and professional fees and insurance expenses.

Other General Expense.During the year ended December 31, 2019, the Fund recorded other general expense of $0.3 million representing its proportionate share of a settlement for a litigation between the Beta Project’s operator and a third-party. Although the Fund was not party to the litigation, the Fund is responsible for its proportionate share of the costs of the litigation as well as any settlement made or judgement imposed upon the operator of the Beta Project if the claim is based upon or arises from operations on the Beta Project.  See Note 5 of “Notes to Financial Statements” – “Commitments and Contingencies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for information regarding this expense.  There was no such amount recorded during the year ended December 31, 2018.

Gain on Sale of Oil and Gas Properties. During the year ended December 31, 2018, the Fund recorded a gain on sale of oil and gas properties of $0.3 million related to the sale of a portion of the Fund’s working interest in the Beta Project. See Item 1. “Business” of this Annual Report under the heading “Beta Project – Partial Sale of Working Interest” for additional information regarding the sale. There was no such amount recorded during the year ended December 31, 2019.

Gain on Debt Extinguishment. During the year ended December 31, 2018, the Fund recorded a gain on debt extinguishment of $2.3 million related to accounting for the third amendment to the credit agreement. See Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Fund’s credit agreement. There was no such amount recorded during the year ended December 31, 2019.

Other Income.  During the year ended December 31, 2018, the Fund recorded other income of $0.1 million related to a fee received upon execution of the Fund’s production handling, gathering and operating services agreement with an affiliated entity and other third parties. There were no such amounts recorded during the year ended December 31, 2019.

Interest Expense, Net. Interest expense, net is comprised of interest expense and amortization of debt discounts related to the Fund’s long-term borrowings, and interest income earned on cash and cash equivalents and salvage fund. See Note 43 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Fund’s credit agreement.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities during the year ended December 31, 20192021 were $6.6$3.0 million, primarily related to revenue received of $9.5$6.2 million, partially offset by the settlement of asset retirement obligations of $1.7 million, operating expenses of $1.5$0.7 million, management fees of $0.9$0.5 million, interest payments of $0.4 million and general and administrative expenses of $0.2$0.1 million and interest payments of $0.1 million.

Cash flows provided by operating activities during the year ended December 31, 20182020 were $9.3$1.6 million, primarily related to revenue received of $12.3$4.3 million, partially offset by operating expenses of $1.4$1.3 million, management fees of $0.9$0.7 million, the payment of $0.3 million related to the Fund’s proportionate share of a settlement for litigation between the Beta Project’s operator and a third-party, interest payments of $0.6$0.3 million and general and administrative expenses of $0.2 million.

Investing Cash Flows

Cash flows used inprovided by investing activities during the year ended December 31, 20192021 were $0.1$0.4 million, related to proceeds from the salvage fund of $1.7 million, partially offset by capital expenditures for oil and gas properties of $0.7$1.0 million and investments in salvage fund of $0.3 million, partially offset by the reimbursement received from operator for capital expenditures of $0.8 million relating to a portion of the cost of the Beta Project platform slot that was utilized by the other third-party working interest owners for the Beta Project’s 8th well. The Fund, as well as other funds managed by the Manager that invested in the Beta Project, elected not to participate in the drilling of the 8th well proposed by the Beta Project operator.million.

Cash flows used in investing activities during the year ended December 31, 20182020 were $3.0$0.3 million, primarily related to capital expenditures for oil and gas properties of $3.5 million and investments in salvage fund of $0.4 million, partially offset by proceeds from sale of oil and gas properties of $0.9 million.fund.

Financing Cash Flows

Cash flows used in financing activities during the year ended December 31, 20192021 were $7.9$4.1 million, related to manager and shareholder distributions of $5.5 million and the repayments of long-term borrowings of $2.4$2.5 million and manager and shareholder distributions of $1.6 million.

Cash flows used in financing activities during the year ended December 31, 20182020 were $4.1$1.9 million, related to manager and shareholder distributions of $1.1 million and the repayments of long-term borrowings of $2.8 million and manager and shareholder distributions of $1.3$0.8 million.

Estimated Capital Expenditures

The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. See Item 1. “Business” of this Annual Report under the heading “Properties” and “Liquidity Needs” below for additional information.

Capital expenditures for oil and gas properties have been funded with the capital raised by the Fund in its private placement offering and through debt financing. The Fund’s capital has been fully allocated to its projects. As a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which it currently has a working interest. Such investment activities, which include estimated capital spending on planned well recompletions for the Beta Project, are expected to be funded from cash flows from operations and existing cash-on-hand and not from equity, debt or off-balance sheet financing arrangements.

See Item 1. “Business” of this Annual Report under the heading “Properties” and “Liquidity Needs” below for additional information.

Liquidity Needs

The Fund’s primary short-term and long-term liquidity needs are to fund its operations and capital expenditures for its oil and gas properties and borrowing repayments.properties. Such needs are funded utilizing operating income and existing cash on-hand.

As of December 31, 2019,2021, the Fund’s estimated capital commitments related to its oil and gas properties were $4.2$3.3 million (which include asset retirement obligations for the Fund’s projects of $3.0$1.6 million), none of which $0.9 million is expected to be spent during the year ending December 31, 2020.2022. Future results of operations and cash flows are dependent on the relatedplanned recompletion costs of and revenues from production and sale of oil and gas revenues from the Beta Project. In addition, cash flow from operations may be impacted by fluctuations in oil and natural gas commodity prices.

Based upon its current cash position, salvage fund and its current reservereserves estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments borrowing repayments and ongoing operations. ReserveReserves estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.

The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. However, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive all or a portion of the management fee at its own discretion.

Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion. However, distributions may be impacted by amounts reserved to provideof future capital required for the borrowing repaymentscosts associated with the well recompletions for the Credit Agreement (defined below) andBeta Project, as budgeted, as well as the funding of estimated asset retirement obligations. Distributions may also be impacted by fluctuations in oil and natural gas commodity prices.

Credit Agreement

The Fund repaid the loan in full including accrued interest as of December 31, 2021. As of December 31, 2019 and 2018,2020, the Fund had outstanding borrowings of $3.3$2.5 million and $5.7 million, respectively, under its credit agreement dated November 27, 2012, as amended on September 30, 2016, September 15, 2017, June 1, 2018 and August 10, 2018 (the “Credit Agreement”).

Borrowings under the Credit Agreement bear interest at 8.75% compounded monthly. Principal and interest payments are based on the fixed percentage of the Fund’s Net Revenue, as defined in the Credit Agreement. Beginning on April 1, 2019 and each April 1^st thereafter, the Fund’s fixed percentage is the greater of (i) 30% or (ii) the Fixed Reassessment Percentage, as defined in the Credit Agreement. The Fixed Reassessment Percentage is determined annually beginning April 1, 2019 and every April 1^st thereafter, and is based on the Fund’s ratio of its outstanding debt as of the reassessment date relative to 80% of third-party reserve engineer’s proved plus probable future undiscounted cash flows attributable to the Beta Project through the maturity of the loan of December 31, 2022. As of April 1, 2019, the Fund’s fixed percentage was determined to be 30%. The loan may be prepaid by the Fund without premium or penalty. The Credit Agreement also provides for a fixed percentage of 8.16% overriding royalty interest to the lenders, which will become payable to the lenders in January 2023, and requires mandatory prepayment of excess cash flows received by the Fund from certain insurance reimbursements, platform related revenues, production handling fees and any additional revenues received with respect to the use of the Beta Project other than any revenues included in the calculation of Net Revenue, as well as proceeds from a sale or transfer of any interest in the Beta Project as permitted under the Credit Agreement.

The Credit Agreement contains customary negative covenants including covenants that limit the Fund’s ability to, among other things, grant liens, change the nature of its business, or merge into or consolidate with other persons. The events which constitute events of default are also customary for credit facilities of this nature and include payment defaults, breaches of representations, warranties and covenants, insolvency and change of control. Upon the occurrence of a default, in some cases following a notice and cure period, the lenders under the Credit Agreement may accelerate the maturity of the loan and require full and immediate repayment of all borrowings under the Credit Agreement. The Fund is in compliance with all covenants under the Credit Agreement as of December 31, 2019 and 2018.

See Note 43 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Credit Agreement.

Off-Balance Sheet Arrangements

Overriding Royalty Interest

The Fund had no off-balance sheet arrangementsCredit Agreement above provides for a fixed percentage of 8.16% overriding royalty interest to the lenders, which will accrue and become payable to the lenders as of December 31, 2019 and 2018 and does not anticipate the use of such arrangements in the future.January 1, 2023.

Contractual Obligations

The Fund enters into participation and joint operating agreements with operators. On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities. The Fund does not negotiate such contracts. No contractual obligations exist as of December 31, 20192021 and 2018,2020, other than those discussed in “Estimated Capital“Capital Expenditures” and “Liquidity Needs –Credit Agreement” above.

Recent Accounting Pronouncements

See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for a discussion of recent accounting pronouncements applicable to the Fund’s financial statements.

Not required.

All financial statements meeting the requirements of Regulation S-X and the supplementary financial information required by Item 302(b) of Regulation S-K are included in the financial statements listed in Item 15. “Exhibits and Financial Statement Schedules” and filed as part of this report.

ITEM 9.       CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Disclosure Controls and Procedures

Under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures as defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, 2019.2021. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures are effective as of the end of the period covered by this report.

Management's Report on Internal Control over Financial Reporting

Management of the Fund is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)).  The Fund’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2019.2021.  In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) inInternal Control — Integrated Framework (2013). Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2019,2021, the Fund’s internal control over financial reporting is effective.

This Annual Report does not include an attestation report of the Fund’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Fund’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Fund, as a non-accelerated filer, to provide only management’s report in this Annual Report.

Changes in Internal Control over Financial Reporting

The Chief Executive Officer and Chief Financial Officer of the Fund have concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, 20192021 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting. The Fund has not experienced any material impact to internal control over financial reporting due to the COVID-19 pandemic.

None.

Not applicable.

PART III

The Fund has engaged Ridgewood Energy as the Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of the Fund and their ages as of December 31, 20192021 are as follows:

The officers in the above table have been officers of the Fund since May 17, 2007, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of the Fund since June 2009. The officers are employed by and paid exclusively by the Manager. Set forth below is certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:

Robert E. Swanson has served as the Chairman, Chief Executive Officer and controlling shareholder of Ridgewood Energy since its inception and is the Chairman of the Investment Committee. Mr. Swanson is also the Chairman of Ridgewood Capital Management, LLC,the Investment Committee of Ridgewood Private Equity Partners, LLC, Ridgewood Infrastructure, LLC and Ridgewood Securities Corporation, affiliatesan affiliate of Ridgewood Energy.Energy. Mr. Swanson is an inactive member of the New York and New Jersey State Bars. He is a graduate of Amherst College and Fordham University Law School.

Kenneth W. Langhas served as the President and Chief Operating Officer of Ridgewood Energy since June 2009 and is a member of the Investment Committee. Effective February 1, 2020, Mr. Lang will relinquishrelinquished the role of Chief Operating Officer of Ridgewood Energy. Prior to joining the Fund, Mr. Lang was with BP for twenty-four years, ultimately serving for his last two years with BP as Senior Vice President for BP’s Gulf of Mexico business and a member of the Board of Directors for BP America, Inc. Prior to that, Mr. Lang was Vice President – Production for BP. After twenty-four years of service to BP, Mr. Lang retired and devoted fifteen months of personal time to pursue and explore other interests. Mr. Lang is a graduate of the University of Houston.

Kathleen P. McSherry has served as the Executive Vice President, and Chief Financial Officer and Assistant Secretary of Ridgewood Energy since 2001. Ms. McSherry holds a Bachelor of Science degree in Accounting from Kean University.

Robert L. Gold has served as a senior officer of Ridgewood Energy since 1987 and is a member of the Investment Committee. Mr. Gold has also served as the President and Chief Executive Officer of Ridgewood Capital since its inception in 1998. Mr. Gold is a member of the New York State Bar. Mr. Gold is a graduate of Colgate University and New York University School of Law.

Daniel V. Gulino is Senior Vice President - Legal Affairs and Secretary for Ridgewood Energy and has served in that capacity for Ridgewood Energy since 2003. Mr. Gulino also serves as Senior Vice President of Legal Affairs of Ridgewood Capital Management, LLC,Ridgewood Private Equity Partners, LLC and Ridgewood Infrastructure, LLCand Senior Vice President & General Counsel of Ridgewood Securities Corporation. Mr. Gulino is a member of the New Jersey State and Pennsylvania State Bars.  Mr. Gulino is a graduate of Fairleigh Dickinson University and Rutgers School of Law.

Board of Directors and Board Committees

The Fund does not have its own board of directors or any board committees. The Fund relies upon the Manager to provide recommendations regarding dispositions and financial disclosure.  Officers of the Fund are not compensated by the Fund, and all compensation matters are addressed by the Manager, as described in Item 11. “Executive Compensation” of this Annual Report.  Because the Fund does not maintain a board of directors and because officers of the Fund are compensated by the Manager, the Manager believes that it is appropriate for the Fund to not have a nominating or compensation committee.

Code of Ethics

The Manager has adopted a code of ethics for all employees, including the Manager’s principal executive officer and principal financial and accounting officer. If any amendments are made to the code of ethics or the Manager grants any waiver, including any implicit waiver, from a provision of the code that applies to the Manager’s executive officers or principal financial and accounting officer, the Fund will disclose the nature of such amendment or waiver on the Manager’s website. Copies of the code of ethics are available, without charge, on the Manager’s website at www.ridgewoodenergy.com and in print upon written request to the business address of the Manager at 14 Philips Parkway, Montvale, New Jersey 07645, ATTN: General Counsel.Legal Department.

The executive officers of the Fund do not receive compensation from the Fund. The Manager and its affiliates compensate the officers without additional payments by the Fund. See Item 13. “Certain Relationships and Related Transactions, and Director Independence” of this Annual Report for more information regarding Manager compensation and payments to affiliated entities.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Percentage of beneficial ownership is based on 332.2918 shares outstanding as of January 31, 2020. The following table sets forth information with respect to beneficial ownership of the Shares as of January 31, 2020 (no other person owns more than 5% of the Shares). The person named in the table below has sole voting and investment power with respect to all Shares shown as beneficially owned by them.2022. No officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the Shares.

ITEM 13.           CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Pursuant to the terms of the LLC Agreement, the Manager renders management, advisory and administrative services to the Fund. For such services, the Manager is entitled to receive an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. Management fees during each of the years ended December 31, 20192021 and 20182020 were $0.9 million.$0.5 million and $0.7 million, respectively.

The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during each of the years ended December 31, 20192021 and 20182020 were $0.8 million and $0.2 million, respectively.million.

Beta S&T, a wholly-owned subsidiary of the Manager, acts as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. In 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third-party purchasers. Pursuant to the master agreement, Beta S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the master agreement or under any other agreements it enters into with regard to the oil and natural gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and natural gas from the Beta Project. The revenues and expenses from the sale of oil and natural gas to third-party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations and are allocable to the Fund based on the Fund’s working interest ownership in the Beta Project.

The Fund and other third-party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) are parties to a production handling, gathering and operating services agreement (“PHA”) with Ridgewood Claiborne, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund II, L.P. (“Institutional Fund II”) and other third-party working interest owners in the Claiborne Project (collectively, the “Producers”), whereby the Beta Project Owners will provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. Institutional Fund II is an entity that is managed by the Fund’s Manager. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018, November 30, 2018 and December 1, 2018). On September 23, 2020, a third-party working interest owner of the Claiborne Project executed a consent letter to assign the rights to the services under the PHA to Ridgewood Rattlesnake, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund III, L.P. (“Institutional Fund III”). Institutional Fund II and Institutional Fund III are entities that are managed by the Fund’s Manager. Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each barrel of oil and mcf of natural gas produced through the Beta Project production facility. See Note 32 of “Notes to Financial Statements” – “Related Parties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the PHA.

At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.

The Fund has working interest ownership in certain oil and natural gas projects, which are also owned by other entities that are likewise managed by the Manager.

Profits and losses are allocated in accordance with the LLC Agreement. In general, profits and losses in any year are allocated 85% to shareholders and 15% to the Manager. The primary exception to this treatment is that all items of expense, loss, deduction and credit attributable to the expenditure of shareholders’ capital contributions are allocated 99% to shareholders and 1% to the Manager.

The following table presents fees for services rendered by Deloitte & Touche LLP during the years ended December 31, 20192021 and 2018.2020.

PART IV

(a) (1)    Financial Statements

See “Index to Financial Statements” set forth on page F-1.

(a) (2)     Financial Statement Schedules

None.

(a) (3)    

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

F-17

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Manager of Ridgewood Energy W Fund, LLC

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Ridgewood Energy W Fund, LLC (the "Fund") as of December 31, 20192021 and 2018,2020, the related statements of operations, changes in members’members' capital, and cash flows, for each of the two years in the period ended December 31, 2019,2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Fund as of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019,2021, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Fund's management. Our responsibility is to express an opinion on the Fund's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Fund in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Fund is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Fund’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Oil and Gas Properties, Depletion and Amortization and Impairment of Long-Lived Assets - Refer to Note 1 to the financial statements

Critical Audit Matter Description

As described in Note 1 to the financial statements, oil and gas properties are accounted for using the successful efforts method. Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities, other than offshore platforms. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs and costs to construct offshore platforms and associated asset retirement costs. Also, the Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Recoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the oil and gas properties at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the oil and gas properties is impaired, and written down to fair value.

Estimates of proved reserves are key components of the Fund’s most significant estimates involving its rate for recording depletion and amortization and estimated future cash flows of oil and gas properties used to test for impairment. Annually, the Fund engages an independent petroleum engineering firm to perform a comprehensive study of the Fund’s proved properties to determine the quantities of reserves and the period over which such reserves will be recoverable. The Fund’s estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions.

The Fund’s oil and gas properties, net balance was $9.3 million as of December 31, 2021 and depletion and amortization expense recognized was $3.9 million for the period ended December 31, 2021. No impairment was recognized during 2021.

We identified the impact of the oil and natural gas reserve quantities on the oil and gas properties and depletion and amortization financial statement line items and the evaluation of impairment of long-lived assets as a critical audit matter due to the significant judgments made by the Fund. The significant judgments made by the Fund include the use of specialists to develop and evaluate the Fund’s oil and natural gas reserve quantities, future cash flows, reserve risk weightings, future development costs, and future oil and natural gas commodity prices. Auditing these significant judgments required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the Fund’s estimates and assumptions related to oil and natural gas reserve quantities included the following, among others:

•

We evaluated the reasonableness of the Fund’s oil and natural gas reserve quantities by performing the following procedures:  

o

Comparing the Fund’s oil and natural gas reserve quantities to historical production volumes.

o

Evaluating the reasonableness of the methodology used and the production volume decline curve.

o

Understanding the experience, qualifications and objectivity of management’s expert, an independent petroleum engineering firm.

o

Comparing forecasts of proved undeveloped oil and gas natural reserves to historical conversions of proved undeveloped oil and natural gas reserves and communication from third-party well operators.

•

We evaluated management’s assessed reserve risk weighting associated with the development of proved, probable and possible oil and natural gas reserve quantities by comparing the assessed risk to industry surveys.  

•

We evaluated the reasonableness of future development costs by comparing such costs to the approval for expenditures, historical well cost data and communication from third-party well operators.

•

We evaluated, with the assistance of our fair value specialists, the reasonableness of future oil and natural gas commodity prices by performing the following procedures:  

o

Understanding the methodology utilized by management for development of the future oil and natural gas commodity prices.

o

Comparing the future oil and natural gas commodity prices to an independently determined range of prices.  

o

Comparing management’s future oil and natural gas commodity prices to published forward pricing indices and third-party industry sources.

•

We evaluated the future oil and natural gas commodity prices by comparing future oil and natural gas commodity price differentials to historical realized price differentials.  

/s/ Deloitte & Touche LLP

Parsippany, New Jersey

March 3, 2020

February 28, 2022

We have served as the Fund's auditor since 2007.

RIDGEWOOD ENERGY W FUND, LLC

BALANCE SHEETS

(in thousands, except share data)

The accompanying notes are an integral part of these financial statements.

RIDGEWOOD ENERGY W FUND, LLC

STATEMENTS OF OPERATIONS

(in thousands, except per share data)

The accompanying notes are an integral part of these financial statements.

RIDGEWOOD ENERGY W FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS'MEMBERS’ CAPITAL

(in thousands, except share data)

The accompanying notes are an integral part of these financial statements.

RIDGEWOOD ENERGY W FUND, LLC

STATEMENTS OF CASH FLOWS

(in thousands)